Vertical seismic profiling (VSP) is a seismic tool that can be used to provide high resolution imaging of a region of a subterranean formation, and is typically used to image petroleum reservoirs. VSP imaging differs from surface seismic imaging in that during VSP data collection, one of the source or the receiver (typically, the receiver) is placed in a borehole in the formation, rather than having the source and receiver both located at the surface. Commonly, a string of geophones or other sensing devices, which act collectively as the receiver, are placed within a borehole during VSP data acquisition. The source can be located at the surface, or in another borehole (in which case the imaging is known as cross-well VSP, also known as cross-well tomography). In the case of an offshore (subsea) reservoir, the source is commonly an air gun placed in the water at or near the surface of the water. If sources are activated in a borehole and the sensing device is located at the surface the configuration is known as Reverse VSP. In the following invention, the meaning of sources and receivers can be interchanged without changing the method itself and is thus applicable to VSP as well as Reverse VSP.
The receiver or receivers in the borehole receive seismic energy produced by the source. The seismic energy arrives at each receiver both as upgoing waves and as downgoing waves. The receiver converts the detected energy into signals which are then transmitted to a data collection location. The signals are typically converted from analog signals to digital signals. The set of digital signals form a VSP data set representative of a region of the formation. This unprocessed VSP data can then be processed using known processing techniques to produce a model of the region, which can be stored on computer readable medium as VSP image data. The VSP image data can be used to generate visual images of the region, and can also be used for computer simulations and the like. Frequently VSP data is augmented with data from a surface seismic survey to produce a higher quality image of a portion of the formation. The seismic image is generated as a result of interaction (reflections, diffractions, conversion, mostly) between the seismic energy from the source and events and structures within the subterranean formation, as well as traveltime of the signals from the source to the receiver (directly or indirectly). An example of a subterranean structure is a geological feature such as a dip, a fold, or a transition from one rock type to another (e.g., from sandstone to granite). A subterranean event can include not only geological features, but also a change in physical properties (e.g., density, porosity, etc.) within the same rock strata. Traveltime is also affected by changes in physical properties within the formation, typically as a function of depth.
The process of seismic interferometry is a method commonly used that retrieves the response of a virtual source by cross correlating responses at two receivers. Interferometry examines the general interference phenomena between pairs of signals in order to gain useful information about the subsurface. Seismic interferometry is used to estimate the detailed properties of media by analyzing the interference patterns of seismic waves. Seismic interferometry utilizes the crosscorrelation of signal pairs to reconstruct the impulse response of a given media. Jon Claerbout's initial (1968) conjecture provided the framework upon which modern interferometric theory is based. Using commonly known seismic interferometry methods, a signal at a first location can be crosscorrelated with a signal at a second location to reproduce a virtual source-receiver pair.
Generally, traveltime is the time lapse between the generation of a seismic signal at a source location and the time at which a seismic receiver receives the signal. As can be appreciated, the density of a geologic formation through which a seismic signal travels has a significant impact on traveltime. A seismic signal will travel faster through a dense formation than it will through a less dense formation. It is therefore very desirable to know the density of a formation through which a seismic signal will travel in order that received signals can accurately indicate the total distance traveled by the signal from the source location prior to being received at a receiver. That is, since the essential objective of reflection seismology is to determine the location (depth) of events in a target area, it is important to have a reasonable approximation or model of the velocities of the different strata involved in the seismic survey. Complicating this process of developing the velocity model is the fact that a geologic formation through which a seismic signal may travel (prior to being received at a receiver) is often not a single layer of a homogeneous material. Rather, the geologic formation typically consists of multiple layers each having different physical properties (typically density) which affect the rate at which a seismic signal propagates through the different layers.
In the case of vertical seismic profiling, it is somewhat relatively straight-forward to determine the signal velocities of different geologic layers within the zone of the receiver array. Referring to FIG. 1, a cross section of a subterranean formation 10 is depicted in a side profile view. The subterranean formation 10 is separated into two regions—an upper region 20 in which a receiver array 14 is placed within a wellbore 12, and a lower region or target area 30 in which no receivers are located. The upper region 20 is bounded at the lower level by the lowest geophone level 46. The target area 30 in general represents an area of interest where more information is desired, typically to identify the potential location of hydrocarbon deposits for exploitation. For practical reasons (typically economic—i.e., the cost of drilling, etc.), the wellbore 12 is not extended into the target area 30, and thus the receiver array 14 is deployed within the upper region 20. Within this upper region 20, it is relatively easy to determine the velocities of different layers within this region. Specifically, a zero-offset checkshot seismic source 18 can be provided at or very near the well head 16 of the wellbore 12. The velocity, v, as measured in meters per second (or other designated units) of a seismic signal traveling through a layer can be determined from the equation:vi≈dli/dτi where dli is the distance between two adjacent receivers 22, identified as ri and ri-1 in the illustration, wherein ri is the upper receiver 22 and ri-1 is the lower receiver 22. Further, dτi is the time difference from reception of the source signal at the upper receiver 22, ri, to when the receiver 22, ri-1, receives the same source signal. Since the distance, dli, between any given receiver, ri and receiver, ri-1, is known, it is possible to determine with some accuracy the various signal velocities within the upper region 20. Of course, the closer the receivers 22 are to one another, the better will be the computed resolution of the signal velocities of the layers within the upper region 20.
In addition to performing a zero-offset survey of the upper region 20 (by providing a source 18 located proximate the wellhead 16 of the wellbore 12), additional velocity information pertaining to both the upper region 20 and the target area 30 can be obtained by performing offset-tomography. In this case, a seismic source 40 is used to generate a seismic signal at a distance “X” from the wellbore 12. Again, since the distances between the source 40 and each of the receivers 22 is known, determining velocities in the upper region 20 is relatively straight forward and somewhat accurate.
However, determining (or approximating) velocities in the target area 30 is somewhat more problematic, since the receiver array 14 does not extend into this area 30. Reflection tomography from an event 44 in the target area 30 will provide signal information to the receiver array 14 indicating the presence of an event 44 in this area, but due to unknowns regarding the velocities and reflector locations in the target area 30, it is difficult to determine accurately the depth of the event reflection point 42 associated with the event 44.
The velocity information received from zero-offset VSP and offset tomography can be supplemented with information from a sonic log of the wellbore 12 if such is available, but such information may be difficult to incorporate since sonic logs are collected at a much higher seismic frequency range than VSP seismic data. Seismic velocity can vary with signal frequency thus causing a comparison of the higher frequency sonic data to VSP data to be indirect. Zero-offset VSP and offset tomography velocity information can also be supplemented with surface seismic velocity analysis information if it is available, but such information lacks the resolution of a VSP survey, and thus does not provide the accuracy desired for improvement of the VSP surveys.
There is therefore a need for a method to improve velocity models used in VSP surveys and associated data processing particularly for determining the presence and location of various seismic reflection or diffraction events within a target area below the depth of an existing wellbore.